Process employing hydrogen to strip dissolved hydrogen sulfide from the liquid effluent of a petroleum distillate hydrotreater

ABSTRACT

The liquid hydrotreated effluent stream from a hydrotreating unit containing dissolved hydrogen sulfide downstream of a high-pressure separator is cooled and reduced in pressure to within a predetermined range before being stripped with process hydrogen to remove the dissolved hydrogen sulfide and recovering the effluent as the final product, the process being particularly suitable for hydrotreating naphtha, kerosene or diesel products to produce an ultra-low sulfur product without the need for further fractionation.

BACKGROUND OF THE INVENTION Field of the Invention

This invention relates to the stripping of hydrogen sulfide from the effluent of a hydrotreater.

Description of Related Art

It is known in the art that strict governmental regulations have been developed requiring reduction of the sulfur content in transportation fuels, including diesel, gasoline and jet fuel. Catalytic hydrotreating of the fuels is a widely applied process used by refineries to reduce organic sulfur to levels of 10 ppm, and below.

Refinery distillates such as diesel from atmospheric distillation side cuts usually contain sulfur in the range of from 0.2 W % to 2.5 W %. In order to produce low-sulfur diesel, Hydrotreating the feed, for example by catalytic hydrogenation, can be carried out to remove sulfur and nitrogen heteroatoms. A trickle bed reactor loaded with a Co/Mo or Ni/Mo catalyst is commonly used for this type of hydrotreating to promote the desired desulfurization, denitrogenation and aromatics saturation reactions to proceed in the reactor. During hydrotreating, the feed is mixed with hydrogen, heated and charged to the top of the reactor. Typical reactor operating conditions include temperatures in the range of from 310° C. to 390° C., pressures in the range of from 30 to 50 bar, and hydrogen-to-oil ratios in the range of from 150-500 Sm3/m3 of feed.

A substantial portion of the organic sulfur and nitrogen content in the feed is converted to hydrogen sulfide (H2S) and ammonia (NH3), respectively, The effluent from the hydrotreating reaction zones) is eventually cooled so that the liquid and gas products can be separated. Although most of the hydrogen sulfide and ammonia produced is recovered in the gas phase in an absorption. process, the remaining., hydrogen sulfide that is dissolved in the liquid-phase reaction product must he removed in order to achieve product specifications. A stripping section or zone is typically used to remove the dissolved hydrogen sulfide from the hydrotreated liquid effluent.

A single reactor vessel is disclosed in US20170009152 that includes an upper hydrotreating catalyst bed, an intermediate zone and a lower catalyst bed with a stripping section in which hydrogen sulfide and ammonia are removed using as a stripping gas that can he a hydrogen-rich gas or steam. The stripping is carried out under conditions that are same as the reaction conditions.

A process is disclosed in U.S. Pat. No. 5,114,562 that employs two reaction zones in series with the effluent from the first zone being purged of hydrogen sulfide by hydrogen gas stripping followed by indirect heat exchange; the second reaction zone employs a sulfur-sensitive noble metal hydrogenation catalyst. The hydrogen stripping conditions include a temperature ranging from 150° C. to 200° C.; following removal of the H2S. the stripping gas is passed to the second reaction zone along with the effluent that has been stripped from the first reaction zone. A hydrogen-rich gas stream is separated from the second reactor effluent and is passed directly to both the first and second reactors. The effluent from the second reactor has a reduced aromatic content.

A steam stripping process is disclosed in U.S. Pat. No. 3,356,608 to remove hydrogen sulfide from the liquid effluent from a hydrotreating reactor. The stripping process involves passing the hydrotreated oil effluent to a stripping zone for steam stripping. at a pressure that is above 200 psig to obtain a bottoms stream that is of substantially lower H₂S content that meets the product specification. An overhead vapors stream comprises H₂S, naphtha, and lighter hydrocarbons.

A hydrocarbon stripping process is disclosed in U.S. Pat. No. 3,719,027 that employs two stripping columns to remove the H₂S from a hydrotreater effluent stream. The effluent stream that comprises light and heavy hydrocarbons is passed to the first stripping column to produce a first stripped stream comprising heavier hydrocarbons and a second overhead stream that comprises the vaporized lighter hydrocarbons and which light hydrocarbon stream is used as a stripping gas stream in the second stripper column, in the second stripper column, a second hydrocarbon stream comprising contaminants and heavy hydrocarbons is stripped. This process requires first obtaining a light hydrocarbon stream for use in a second stripper for stripping the contaminated hydrocarbon.

A process is disclosed in U.S. Pat. No. 6,550,252 for generating power from a liquid hydrocarbon stream derived from a hydroprocessing, hydrodesulforization, hydrocracking, catalytic reforming, or other process: in which hydrogen is reacted with hydrocarbons in a manner such that small quantities of volatile hydrocarbons and hydrogen are dissolved in a liquid hydrocarbon. The process includes stripping the hydrocarbon liquid with an inert gas such as nitrogen to produce a treated hydrocarbon liquid stream and separating the stripping gas that contains all or a substantial portion of the volatile hydrocarbons and hydrogen that have been removed from the liquid hydrocarbon stream the latter being mixed with a fuel gas and combusted to drive a turbine to generate electric power.

In a refinery, a typical hydrotreating unit comprises a reaction section, a hydrogen-rich gas sweetening and recycling section, and a liquid product stripping section.

In the reaction section, the liquid feed is mixed with a hydrogen-rich recycle gas and fresh make-up hydrogen as needed, the hydrogen being passed through a preheater and charged to the hydrotreating reactor. The effluent from the reactor is typically cooled via a heat exchanger and is charged to a high-pressure separator where a gas-phase stream and a liquid-phase stream are separated.

The gas-phase stream from the high-pressure separator is typically sent to a gas sweetening zone that removes hydrogen sulfide in the gas phase using an amine absorbent. The sweetened gas, comprising principally hydrogen can be compressed and recycled to the reactor. A fresh hydrogen stream is added at this stage as make-up hydrogen to compensate for the hydrogen consumed during the hydrotreating reaction.

The liquid-phase stream from the high-pressure separator contains dissolved hydrogen sulfide. in the processes of the prior art, the liquid phase of the reactor effluent is typically charged to a stripping section to remove the dissolved hydrogen sulfide. The stripping section is a vessel or column in which steam is injected in the bottom to strip out the dissolved hydrogen sulfide from the liquid-phase stream, An outlet gas stream comprising water vapor and hydrogen sulfide is cooled to condense the water and the hydrogen sulfide is separated from the steam and sent to a low-pressure amine sweetening section for hydrogen sulfide removal. The water condensed from the steam is recycled for reuse in the processor. The liquid product having a low sulfur content is recovered from the bottom of the stripping column.

In the prior art, water is heated to form steam that is used as the stripping medium. The circulation and heating of the water to form steam requires a significant amount of energy and requires a capital investment in boiler and/or heat exchange devices, pumps and heaters. Handling and pumping sour water through the system causes corrosion to pipes and vessels which are typically made of high alloy material. The removal of waste water from the hydrotreating system has associated environmental and pollution problems, and additional equipment and energy are needed to treat the waste water for disposal.

In order to increase the efficiency of multiple hydrotreaters operated in series to remove light hydrocarbon including H₂S from the hydrotreated effluent, the use of hydrogen gas as a stripping medium has been disclosed. When hydrogen or a hydrogen-rich gas stream is used as the stripping gas, the stripper is either integrated between reactors , or combined with a fractionator for removing the light hydrocarbons, and is operated at temperatures in the range of 140-450° C., and pressures over 10 bar, and typically in the range of the reaction pressure. In the typical refinery hydrotreating unit, the flow rate of hydrogen needed is predetermined by the hydrogen-to-oil ratio and is much higher than the stoichiometric ratio needed for completion of the hydrotreating reaction. Unreacted hydrogen-rich gas that typically contains some light hydrocarbon gas is sweetened by amine absorption and then recompressed and recycled to the reactor. A fresh stream of make-up hydrogen is added to the stream that is recycled to the reactor.

In most hydrotreating processes, the hydrotreated effluent contains a significant quantity of light hydrocarbons that are removed by a fractionation column or a steam stripper, or a combination of both, all of which are operated at a high temperature. Hydrogen stripping has no advantage when compared to steam stripping because the stripping hydrogen contaminated with H₂S increases the volume of the gases that must be subjected to amine absorption. Since the new requirement for low and ultra-low sulfur fuel has become mandatory, some ultra-low sulfur hydrotreating processes using high level sulfur fuels as the feed are being operated in some refineries. Steam stripping of the hydrotreated effluent is being used in conjunction with the ultra-low sulfur fuel hydrotreating units.

As used herein the terms stripping column, stripping unit, stripping zone and stripper are synonymous and can be used interchangeably.

SUMMARY OF THE INVENTION

The above needs are met and other advantages are provided by the process of the present disclosure in which the liquid hydrotreated effluent stream from a hydrotreating unit containing dissolved hydrogen sulfide is cooled and reduced in pressure to within predetermined ranges before being stripped with process hydrogen to remove dissolved hydrogen sulfide from the effluent.

More specifically, the process comprises catalytically hydrotreating a sulfur-containing feed stream separating the liquid portion of the hydrotreated stream in a high pressure separator, cooling and reducing the pressure of the liquid portion, stripping the cooled liquid stream at a pressure within a predetermined range with hydrogen gas to remove hydrogen sulfide from the liquid effluent, recovering a product stream of reduced sulfur content, separating the hydrogen sulfide from the hydrogen, and recycling the hydrogen for use in the hydrotreating process, or in other refinery processes.

In certain embodiments, the invention is particularly suitable for the hydrotreatment of naphtha, kerosene or diesel products to produce an ultra-low sulfur product without the need for farther fractionation.

The present disclosure. comprehends a process for the treatment of a sulfur-containing hydrocarbon feed stream to reduce its sulfur content that comprises:

-   -   a. mixing the sulfur-containing feedstream and a high-pressure         hydrogen-rich stream to produce a mixed feed and charging the         mixed feed to a hydrotreating zone to produce a hydrotreating         zone effluent;     -   b. introducing the hydrotreating zone effluent into a cooling         zone to a temperature in the range of from 20° C. to and then to         a high-pressure separation zone recovering a gas phase effluent         comprising excess hydrogen and hydrogen sulfide gases and a         liquid phase effluent comprising hydrogen sulfide dissolved in         the hydrotreated hydrocarbon;     -   c. passing the gas phase effluent comprising hydrogen sulfide         gas from the high-pressure separation zone to a high-pressure         amine absorbent zone to remove the hydrogen sulfide gas from the         gas phase effluent and recovering a sweetened hydrogen-rich gas         stream;     -   d. mixing, the sweetened hydrogen-rich gas stream with a         hydrogen-rich stripping unit recycle stream to form a         hydrogen-rich mixed recycle stream;     -   e. compressing the hydrogen-rich mixed recycle stream. in a         recycle compressor to produce the high-pressure hydrogen-rich         stream of step (a);     -   f. passing the liquid phase effluent containing dissolved         hydrogen sulfide from the high-pressure separator through a         control valve to reduce the pressure to provide a cooled         hydrotreated liquid effluent stream comprising dissolved         hydrogen sulfide that is at a temperature in the range of from         20° C. to 80° C. and at a pressure in the range of from 0 bar to         10 bar;     -   g. passing the cooled hydrotreated effluent stream containing         dissolved hydrogen sulfide and a hydrogen stripping stream to a         stripping zone to strip the dissolved hydrogen sulfide from the         cooled hydrotreated effluent stream and recovering a cooled         hydrotreated liquid product that is substantially free of H₂S         and a top stream comprising hydrogen sulfide, hydrogen and light         hydrocarbons; and     -   h. removing the hydrogen sulfide from the top stream in a         low-pressure amine absorber to produce the hydrogen-rich         stripping unit recycle stream of step (d).

BRIEF DESERIPTIORE OF THE DRAWINGS

The invention will be described in greater detail below and with reference to the attached drawings in which:

FIG. 1 is a simplified schematic diagram of a hydrotreating unit operation in accordance with an embodiment of the present disclosure;

FIG. 2 is a simplified schematic diagram of a hydrotreating unit operation in accordance with another embodiment of the present disclosure; and

FIG. 3 is a simplified schematic diagram of a stripping unit that is suitable for use in the process of the present disclosure.

In the description of the figures that follows, the same or similar elements are identified by a similar series of numbers, for example, feedstream (102, 202).

DETAILED DESCRIPTION OF THE INVENTION

Referring now to the schematic illustration FIG. 1, a process in accordance with an embodiment of the present disclosure for treating the liquid effluent stream from a hydrotreater containing dissolved hydrogen sulfide will be described.

A sulfur-containing hydrocarbon feed stream (102) is mixed with a stream of hydrogen-rich gas (104) and the heated mixture (106) is fed into a hydrotreating reactor (110). The organic sulfur and any nitrogen compounds in the feed are converted to hydrogen sulfide gas and ammonia gas, respectively. The reactor effluent (112) is cooled to a temperature in the range of from 20° C. to 80° C. by one or more heat exchangers (114) and enters high-pressure separator (116). The gas phase (122) from the high-pressure separator is sent to a conventional high-pressure amine absorber (120) of the prior art to remove the hydrogen sulfide in the gas phase. After sweetening of the gas in the high pressure amine absorber section (120), the sweetened hydrogen-rich recycle gas stream (124) comprises a major portion of hydrogen and some hydrocarbon gas that is combined with a stripper recycle stream (136) and passed to compressor (108) to provide high pressure hydrogen recycle stream (104) to hydrotreating reactor (110).

The liquid phase (118) from the high-pressure separator (116) contains dissolved hydrogen sulfide and is passed to level control valve (150) to produce a cool relatively low-pressure stream (158). The cool and reduced pressure stream (158) is charged to a stripping unit (140) to remove the dissolved hydrogen sulfide. The stripping unit can be a column with several trays or a column packed with distillation packing materials. A hydrogen stream (144) is injected into the bottom of the stripper, and the cool stream (158) is introduced into the top of the unit and passes in counter-current flow to the hydrogen. In some embodiments, the cool stream (158) of reduced pressure is at a temperature in the range of from 20° C. to 80° C. and at a pressure in the range of from 0 bar to 10 bar.

In the stripper (140), which will be described in more detail below, hydrogen gas (144) flows upwardly and is in intimate contact with the cool hydrogen sulfide-containing stream (158) that is flowing downwardly, The dissolved H₂S gas is stripped from stream (158) and enters the gas phase which is withdrawn with hydrogen and any light hydrocarbons from the top of the stripper as a tops stream (142). The hydrotreated liquid hydrocarbon that is substantially free of dissolved hydrogen sulfide is discharged from the bottom of the unit as the product stream (146), or sent for further downstream processing (not shown). The tops stream (142) containing hydrogen sulfide exits the unit (140) and enters into a low-pressure; amine absorber (130) to remove the hydrogen sulfide gas. The remaining tinny-free hydrogen gas stream (132) 1s then passed to compressor (134) where the pressure is increased to that of recycle gas stream (124) from high pressure amine absorber section (120). Stripping gas (136) then joins separator gas (124) to form recycled hydrogen-rich gas (126). The hydrogen-rich gas (126) is compressed in compressor (108) and is recycled to reactor (110) as stream (104).

In this embodiment, the gas-flow rate to the stripping column is determined by the make-up hydrogen flow rate. The make-up hydrogen flow rate is determined by the hydrogen consumption rate of the hydrotreating reaction. The consumption of hydrogen for the hydrotreating reaction is normally in the range of from 0.2 W % to 1.0 W % of the weight of the initial oil feed which can be converted to a volume ratio in the range of from of 18 Sm³/m³ of oil to 95 Sm³/m³ of oil, Preferably, the ratio of hydrogen (144) sent to the stripper to feed oil is in the range of from 20 to 60 Sm³/m³ of feed oil.

Referring now to the schematic illustration of FIG. 2, a process will be described in accordance with another embodiment of the present disclosure fir treating the liquid effluent stream from a hydrotreater to remove dissolved hydrogen sulfide.

This embodiment is similar to the embodiment depicted in FIG. 1, with the same or similar elements identified by a similar series of numbers. In this embodiment, a portion, preferably from 5% to 30% of stripping gas (238) from the low pressure amine absorber (230) is recycled to combine with make-up hydrogen gas (244) to be injected as combined stream (248) into stripper (240) to enhance the flow rate of stripping gas to the stripper. In this embodiment, the fresh make-up hydrogen (244) is not sufficient to efficiently remove all of the H₂ 8 from the cool, relatively low-pressure stream (258), the introduction of additional hydrogen gas from low-pressure amine absorber (230) will increase the efficiency of the hydrogen sulfide removal process.

In this system, the stripping gas (238) downstream from the low-pressure amine absorber (230) is split into two streams, (236) and (260) via a splitter valve (235). Recycle stream (236) is recycled to the hydrotreating reactor (210) as described above in connection with FIG. 1; return stream. (260) is recycled to combine with make-up hydrogen gas, stream (244) to supplement stripping gas stream (248) that is introduced into the bottom of stripping unit (240).

In this embodiment which is similar to that depicted in FIG. 1, stream (258) is at a temperature in the range of from 20° C. to 80° C. and a pressure in the range of from 0 bars to 10 bar,

Referring now to the schematic illustration of FIG. 3, the stripping unit employed in the present invention will be described. As shown, the stripping, unit (340) is in the form of a column that is packed with a commercially available distillation packing material (366) and includes a feed injection port (368) and feed distributor (364) in the upper section. The column packing materials can be random packing using small pieces of packing materials, or preferably, structured packing, such as SULZER Structured Packings. The choice and selection of the packing material is a within the skill of the art. The cooled stream (358) enters the stripper through the feed injection port (368), and hydrogen gas (348) is injected into the bottom of the column and flows upwardly through the packing material (366) and displaces dissolved hydrogen sulfide which is transferred to the gas phase and flows upwardly to the top of column (340) with the excess hydrogen and any trace amounts of light hydrocarbons remaining in the effluent stream, all of which are withdrawn from stripper (340) as gaseous effluent stream (342) and sent to the low-pressure amine absorber (330) for removal of the sulfur and recovery of the hydrogen stream (332) for treatment as described above in connection with FIGS. 1 and 2.

The treated effluent product (346) that is free or substantially free of hydrogen sulfide is withdrawn from the bottom of the stripper column (340), e.g., via a level control device (not shown). The stream (346) can be passed directly to the fuel blending pool as the finished product or can be passed for further downstream processing, e.g., fractionating.

The height of the stripper column (340) depends on the number of theoretical plates required for efficient separation of the H₂S and the height of packing equivalent to one theoretical plate (HETP), the value of the latter being provided by the manufactures of various types of packing materials. The minimum number of theoretical plates recruited for practice of the present process is 4; the number of theoretical plates is preferably in the range of from 6 to 12.

The process can be practiced in a stripping column that is constructed with distillation plates to effect the mass transfer of the H₂S to the gas phase from the hydrotreated liquid phase.

In accordance with the process of the present disclosure, the stripping column is operated at a temperature in the range of from 20° C. to 80° C., and at an operating pressure in the range of from zero to ten bar, and preferably from one bar to five bar.

The feed streams (102, 202) can be any suitable feed such as naphtha, kerosene or diesel.

The hydrotreating reactor or zone (110, 210) can contain one or more fixed-bed hydrotreating reactors loaded with solid hydrotreating catalyst. The present hydrotreating process is specially adapted for the removal of sulfur- and nitrogen-containing, compounds from petroleum distillates and is preferably used for removing sulfur from naphtha, kerosene or diesel to produce ultra-low sulfur level fuels and/or fuel blending products.

Thus, in accordance with the present disclosure, a process for hydrotreating to produce ultra-low sulfur fuels and/or blending products is provided in which the effluent from the hydrotreater doesn't require fractionation and is cooled to temperatures as low as ambient. Sweetened hydrogen or make-up hydrogen can be used as the stripping gas to remove the dissolved H₂S in the liquid product at a relatively low temperature and low pressure. The use of hydrogen for stripping the hydrotreated effluent has several advantages in addition to those of operating at low temperature and low pressure, including that it is simple and clean. The process is especially adapted for use as the last step in the production of an ultra-low sulfur fuel after hydrotreating without further treatment. The stripped liquid effluent is then recovered as the final product.

EXAMPLES Example 1

In order to demonstrate the use and benefits of hydrogen stripping in accordance with the process of the present disclosure, a computer simulation employing Aspen HYSYS® V10.0 was conducted using a diesel stream containing 1.0 W % of sulfur as a feed to the hydrotreating zone to remove the sulfur.

Table 1 shows the mass balance and properties of the feedstream employed in the simulation included a diesel feed flow of 1.0 m³/h and a hydrogen gas flow rate of 316 Sm³/h providing a ratio of H₂-to-oil for hydrotreating of 316 Sm³/m³ of oil.

In the simulation, the hydrotreater and high-pressure separator units produced a stream, i.e., the cooled and low-pressure stream (158), that contains 2690 ppm of H₂S. The effluent is introduced into the top of the stripper via a distribution device. Make-up hydrogen gas is injected into the bottom of the stripper via a conventional distribution manifold. The flow rate of make-up hydrogen stream (144) is determined by the consumption of hydrogen during hydrotreating. In this example, the consumption of hydrogen during hydrotreating is 0.5 wt % of the diesel feed. The stripper, which has 10 theoretical plates or stages, is operated at ambient temperature. The hydrotreated. liquid hydrocarbon product stream (146), i.e., the hydrotreated diesel that has been stripped of H₂S, is withdrawn from the bottom of the column with an H₂S content of less than 1 ppmw.

TABLE 1 Hydro- Hydro- treater Make-up Stripping treated Unit Diesel H₂ Effluent H2 Gas Diesel Stream 102 104 158 144 142 146 Vapor 0 1 0.031779594 1 1 0 Fraction Temp. ° C. 40.0 40.0 40.0 30.0 39.7 39.2 Pressure bar 40.0 40.0 2.0 2.2 2.0 2.2 Molar Flow gmol/h 3771.33 13384.49 3943.38 2089.77 2261.02 3772.12 Mass Flow kg/h 836.37 26.98 838.67 4.21 7.15 835.74 Liq. Vol. m³/h 1.00 1.01 — — 1.00 Flow Std. Gass Sm³/h — 316.5 — 49.4 53.5 — Flow H₂S ppm, 0.0 0.0 2690.4 0.0 315755.9 0.0 Content wt H₂ Content wt % 0.0 100.0 0.0 100.0 61.8 0.0

Example 2

In this Example, the ratio of make-up hydrogen flow-to-feed oil was varied from Example 1 in order to illustrate how the flow rate of H₂ stripping gas affects the removal of dissolved H₂S in the hydrotreated diesel product of the HYSYS simulation. The results are presented in Table 2. It can be seen that the lowest ratio of hydrogen stripping gas to liquid feed required to obtain a final product containing less than 1 ppm Wt of H₂S is 15 Sm³/m³ of oil.

TALBE 2 Ratio of Flow of Make-up H2 to Hydrotreated Liquid Feed to Diesel H₂S stripper, Sm³/m³ content, ppm Case of oil Wt Case 1 5 1444.11 Case 2 10 27.49 Case 3 15 0.88 Case 4 20 0.063 Case 5 25 0.008 Case 6 30 0.001 Case7 35 3.07E−04 Case 8 40 8.42E−05 Case 9 45 2.68E−05 Case 10 50 9.59E−06

Example 3

In this Example, Case 10 from Example 2, i.e., with a ratio of hydrogen stripping gas flow to liquid feed of 50 Sm³/m³ was investigated to determine the impact of the number of theoretical plates required in order to obtain a final hydrotreated product containing less than about 1 ppm of dissolved H₂S. As shown by the results in Table 3, the minimum number theoretical plates required is 4.

TABLE 3 Number of H₂S Content in Theoretical Plates in Hydrotreated Diesel, Case Stripping Column ppm Wt Case 1 2 32.88 Case 2 3 4.01 Case 3 4 0.49 Case 4 5 0.06 Case 5 6 0.007

Example 4

In this Example, Case 4 from Example 3, i.e., with a ratio of hydrogen stripping gas flow to liquid feed of 50 Sm³/m³ and 5 theoretical plates in the stripping column was investigated to determine the effect of the pressure of the stripping column required in order to obtain a final hydrotreated product containing less than about 1 ppm of dissolved H₂S. As shown by the results in Table 4 when pressure is over 5 bar, the H₂S content dissolved in hydrotreated diesel product is more than 1 ppm.

TABLE 4 Pressure of the H₂S Content in Stripping Column, Hydrotreated Diesel, Case bar ppm Wt Case 1 1 0.002 Case 2 3 0.31 Case 3 5 3.34 Case 4 7 15.10 Case 5 9 43.86

Example 5

In this Example, Case 4 from Example 3, i.e., with a ratio of hydrogen stripping gas flow to liquid feed of 50 Sm³/m³, with 5 theoretical plate in the stripping column and an operating pressure of 2.0 bar was investigated to determine the effect of the temperature of the stripping column required in order to obtain a final hydrotreated product containing less than about 1 ppm of dissolved H₂S. As shown by the results in Table 5, with increasing temperature, the H₂S content in hydrotreated diesel product is decreased. Within the range of the case studies, each of the H₂S levels is lower than I ppm. However, increased temperatures will cause the liquid product will lose light components, and that should be avoided.

TABLE 5 Temperature of H₂S Content in the Stripping Hydrotreated Diesel, Case Column, ° C. ppm Wt Case 1 20 0.279 Case 2 30 0.108 Case 3 40 0.057 Case 4 60 0.009

This example shows that the stripping process of the present disclosure is capable of being operated at low temperatures at the last stage of the hydrotreating unit before the final liquid product is discharged to storage or transportation.

The improved process and system of this disclosure has been described above and illustrated in the attached drawings from which modifications and variation will be apparent to those of ordinary skill in the art, and the scope of protection for the process and system is to be determined by the claims that follow. 

1. A process for the treatment of a sulfur-containing liquid hydrocarbon feedstream to reduce its sulfur content, where the feedstream is naphtha, kerosene or diesel, the process comprising: a. mixing the sulfur-containing liquid feedstream and a high-pressure hydrogen-rich stream to produce a mixed feed and charging the mixed feed to a hydrotreating zone to produce a hydrotreating zone effluent; b. introducing the hydrotreating zone effluent into a cooling zone and then into a high-pressure separation zone and recovering a gas phase effluent comprising excess hydrogen and hydrogen sulfide gases and a liquid phase effluent comprising hydrogen sulfide dissolved in the hydrotreated hydrocarbon; c. passing the gas phase effluent comprising hydrogen sulfide gas from the high-pressure separation zone to a high-pressure amine absorbent zone to remove the hydrogen sulfide gas from the gas phase effluent and recovering a sweetened hydrogen-rich gas stream; d. mixing the sweetened hydrogen-rich gas stream with a hydrogen-rich stripping unit recycle stream to form a hydrogen-rich mixed recycle stream; e. compressing the hydrogen-rich mixed recycle stream in a recycle compressor to produce the high-pressure hydrogen-rich stream of step (a); f. passing the liquid phase effluent containing dissolved hydrogen sulfide from the high-pressure separator through a control valve to reduce the pressure to provide a cooled hydrotreated liquid. effluent stream comprising dissolved hydrogen sulfide that is at a temperature in the range of from 20° C. to 80° C. and at a pressure in the range of from 0 bar to 10 bar; g. passing the cooled hydrotreated effluent stream containing dissolved hydrogen sulfide and a stripping stream consisting of hydrogen to a stripping zone to strip the dissolved hydrogen sulfide from the cooled hydrotreated effluent stream and recovering a cooled hydrotreated liquid ultra-low sulfur fuel product containing 10 ppmw or less of sulfur that is substantially free of H₂S and a top stream comprising hydrogen sulfide, hydrogen and light hydrocarbons; and h. removing the hydrogen sulfide from the top stream in a low-pressure amine absorber to produce the hydrogen-rich stripping unit recycle stream of step (d).
 2. (canceled)
 3. (canceled)
 4. The process of claim 1, wherein the temperature of the hydrotreating zone effluent is reduced in the cooling zone of step (b) to a temperature of from 20° C. to 80° C.
 5. The process of claim 1, wherein the temperature of the hydrotreating zone effluent is reduced by passing the effluent through one or more heat exchangers.
 6. The process of claim 1, wherein the stripping zone comprises a column having a plurality of trays or a packed column containing packing material through which the cooled hydrotreated effluent stream containing dissolved hydrogen sulfide passes in descending counter-current flow with ascending hydrogen stripping gas that displaces the hydrogen sulfide from the effluent stream.
 7. The process of claim 6, wherein the operating conditions of temperature and pressure in the stripping zone are predetermined based upon the characteristics of the packing material loaded into the packed column or the configuration and number of trays in the column.
 8. The process of claim 7, wherein the operating conditions are predetermined on the basis of theoretical plate calculations.
 9. The process of claim 8, wherein the number of theoretical plates is between 4 and 10 to achieve a sulfur content of less than 1 ppmw.
 10. The process of claim 1, wherein all or a portion of the hydrogen.-rich stripping unit recycle stream of step (e) is mixed with a fresh hydrogen stream to produce the stream of stripping hydrogen for use in step (g).
 11. A system for the production of ultra-low sulfur hydrocarbon product streams from sulfur-containing liquid hydrocarbon feedstream that comprises: a. a hydrotreating zone containing a catalyst adapted for receiving a mixture of the sulfur-containing liquid hydrocarbon feedstream and a high-pressure hydrogen-rich stream and for discharging a hydrotreating zone effluent; b. a cooling zone in fluid communication with the hydrotreating zone and adopted for receiving and cooling the hydrotreating zone effluent; c. a high-pressure separation zone in fluid communication with the cooling zone and adapted for receiving the cooled hydrotreating zone effluent and discharging a gas phase effluent comprising excess hydrogen and hydrogen sulfide gases and a separate liquid phase effluent comprising the hydrotreated hydrocarbon stream containing dissolved hydrogen sulfide; d. pressure reducing means in fluid communication with the high-pressure separation zone and adapted to receive and reduce the pressure of the liquid-phase hydrotreated hydrocarbon stream containing dissolved hydrogen sulfide to a predetermined lower pressure; e. a stripping zone in fluid communication with the pressure reducing means and adapted to: i. receive and pass the hydrotreated hydrocarbon stream containing dissolved hydrogen sulfide in counter-current flow with a hydrogen stripping stream; ii. discharge a stripping zone top stream comprising hydrogen sulfide, hydrogen and light hydrocarbons; and discharge a stripping zone bottom stream that is a cooled hydrotreated hydrocarbon product that is substantially free of hydrogen sulfide.
 12. The system of claim 11 which includes a low-pressure amine absorber in fluid communication with the stripping zone top stream and adapted to remove the hydrogen sulfide and discharge a hydrogen-rich amine absorber recycle stream.
 13. The system of claim 12 which includes a recycle compressor in fluid communication with the low-pressure amine absorber and a high-pressure amine absorption zone, and adapted to receive the hydrogen-rich recycle stream, and to mix and compress it with a sweetened hydrogen stream recovered from the high-pressure amine absorbent zone to form a hydrogen-rich mixed recycle stream.
 14. The system of claim 11 in which the stripping zone includes a column that operates with the equivalent of at least 4 theoretical plates.
 15. The system of claim 14 in which the stripping zone includes a column that operates with the equivalent of 6 to 12 theoretical plates. 